US10267517B2 - Method and system for improving boiler effectiveness - Google Patents

Method and system for improving boiler effectiveness Download PDF

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Publication number
US10267517B2
US10267517B2 US15/205,243 US201615205243A US10267517B2 US 10267517 B2 US10267517 B2 US 10267517B2 US 201615205243 A US201615205243 A US 201615205243A US 10267517 B2 US10267517 B2 US 10267517B2
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United States
Prior art keywords
flue gas
air
temperature
air preheater
steam generator
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US15/205,243
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US20180010792A1 (en
Inventor
Kevin O'Boyle
Glenn D. Mattison
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Arvos Ljungstroem LLC
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Arvos Ljungstroem LLC
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Priority to US15/205,243 priority Critical patent/US10267517B2/en
Priority to PCT/US2016/055958 priority patent/WO2018009233A1/en
Priority to JP2019500294A priority patent/JP2019520543A/ja
Priority to PL17705500T priority patent/PL3482124T3/pl
Priority to SI201730533T priority patent/SI3482124T1/sl
Priority to ES17705500T priority patent/ES2830731T3/es
Priority to GBGB1901689.8A priority patent/GB201901689D0/en
Priority to PL42957217A priority patent/PL429572A1/pl
Priority to ES201990005A priority patent/ES2738919B1/es
Priority to AU2017291660A priority patent/AU2017291660A1/en
Priority to US16/316,215 priority patent/US10955136B2/en
Priority to CN201780000143.4A priority patent/CN107923610B/zh
Priority to EP17705500.1A priority patent/EP3482124B1/en
Priority to PCT/US2017/013459 priority patent/WO2018009247A1/en
Priority to KR1020197002188A priority patent/KR20190024970A/ko
Priority to PCT/US2017/041078 priority patent/WO2018009781A1/en
Priority to PL429398A priority patent/PL241095B1/pl
Priority to EP17743120.2A priority patent/EP3482125B1/en
Priority to AU2017292939A priority patent/AU2017292939A1/en
Priority to GB1901694.8A priority patent/GB2567104B/en
Priority to PCT/US2017/041332 priority patent/WO2018009926A1/en
Priority to JP2019500309A priority patent/JP7152121B2/ja
Priority to CN201780041628.8A priority patent/CN110036238B/zh
Priority to US16/316,170 priority patent/US20210285637A1/en
Priority to KR1020197002327A priority patent/KR102474929B1/ko
Priority to ES201990006A priority patent/ES2745035R1/es
Publication of US20180010792A1 publication Critical patent/US20180010792A1/en
Assigned to ARVOS LJUNGSTROM LLC reassignment ARVOS LJUNGSTROM LLC ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: MATTISON, GLENN D., O'BOYLE, KEVIN
Priority to ZA201900378A priority patent/ZA201900378B/en
Priority to ZA2019/00427A priority patent/ZA201900427B/en
Publication of US10267517B2 publication Critical patent/US10267517B2/en
Application granted granted Critical
Assigned to LUCID TRUSTEE SERVICES LIMITED reassignment LUCID TRUSTEE SERVICES LIMITED SECURITY INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: ARVOS LJUNGSTROM LLC
Priority to JP2021185614A priority patent/JP7207810B2/ja
Priority to AU2023202632A priority patent/AU2023202632A1/en
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    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/30—Controlling by gas-analysis apparatus
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/48—Sulfur compounds
    • B01D53/50—Sulfur oxides
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/48—Sulfur compounds
    • B01D53/50—Sulfur oxides
    • B01D53/501—Sulfur oxides by treating the gases with a solution or a suspension of an alkali or earth-alkali or ammonium compound
    • B01D53/502—Sulfur oxides by treating the gases with a solution or a suspension of an alkali or earth-alkali or ammonium compound characterised by a specific solution or suspension
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F1/00—Treatment of water, waste water, or sewage
    • C02F1/02—Treatment of water, waste water, or sewage by heating
    • C02F1/04—Treatment of water, waste water, or sewage by heating by distillation or evaporation
    • C02F1/10—Treatment of water, waste water, or sewage by heating by distillation or evaporation by direct contact with a particulate solid or with a fluid, as a heat transfer medium
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/008—Adaptations for flue gas purification in steam generators
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F22B37/025—Devices and methods for diminishing corrosion, e.g. by preventing cooling beneath the dew point
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22D—PREHEATING, OR ACCUMULATING PREHEATED, FEED-WATER FOR STEAM GENERATION; FEED-WATER SUPPLY FOR STEAM GENERATION; CONTROLLING WATER LEVEL FOR STEAM GENERATION; AUXILIARY DEVICES FOR PROMOTING WATER CIRCULATION WITHIN STEAM BOILERS
    • F22D1/00—Feed-water heaters, i.e. economisers or like preheaters
    • F22D1/36—Water and air preheating systems
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00—Arrangements of devices for treating smoke or fumes
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00—Arrangements of devices for treating smoke or fumes
    • F23J15/02—Arrangements of devices for treating smoke or fumes of purifiers, e.g. for removing noxious material
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00—Arrangements of devices for treating smoke or fumes
    • F23J15/02—Arrangements of devices for treating smoke or fumes of purifiers, e.g. for removing noxious material
    • F23J15/022—Arrangements of devices for treating smoke or fumes of purifiers, e.g. for removing noxious material for removing solid particulate material from the gasflow
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00—Arrangements of devices for treating smoke or fumes
    • F23J15/06—Arrangements of devices for treating smoke or fumes of coolers
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00—Arrangements of devices for treating smoke or fumes
    • F23J15/08—Arrangements of devices for treating smoke or fumes of heaters
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23K—FEEDING FUEL TO COMBUSTION APPARATUS
    • F23K1/00—Preparation of lump or pulverulent fuel in readiness for delivery to combustion apparatus
    • F23K1/04—Heating fuel prior to delivery to combustion apparatus
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L15/00—Heating of air supplied for combustion
    • F23L15/04—Arrangements of recuperators
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2215/00—Preventing emissions
    • F23J2215/20—Sulfur; Compounds thereof
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2217/00—Intercepting solids
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L2900/00—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber
    • F23L2900/15043—Preheating combustion air by heat recovery means located in the chimney, e.g. for home heating devices
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00—Combustion technologies with mitigation potential
    • Y02E20/30—Technologies for a more efficient combustion or heat usage
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00—Combustion technologies with mitigation potential
    • Y02E20/34—Indirect CO2mitigation, i.e. by acting on non CO2directly related matters of the process, e.g. pre-heating or heat recovery

Definitions

  • the present invention relates generally to a method and system for improving the effectiveness of a fossil fuel fired steam generator and the effectiveness of particulate removal, and is more particularly directed to a method and system for improving the effectiveness of an air preheater by reducing fouling and improving the thermal efficiency of the fossil fuel fired steam generator and the efficiency of an electro-static precipitator by using SO 3 mitigation upstream of the air preheater, excess air to the air preheater and stack gas reheat to thereby eliminate one or more heat exchangers and eliminate one or more fans downstream of the air preheater.
  • APH Air Preheater
  • Efficiency of the APH can be increased by using higher efficiency heat transfer elements and heat transfer elements with a greater heat transfer area.
  • those skilled in the relevant art have not been able to realize the full potential of increased APH efficiency available through the use of higher efficiency heat transfer elements and greater heat transfer area of the heat transfer elements, because of operation limitations relating to the control of pollutants, as described herein.
  • the byproducts in the flue gas stream can include particulate matter and pollutants.
  • the combustion of coal results in combustion byproducts such as particulate matter in the form of fly ash and pollutants such as nitrogen oxides (NO X ), sulfur dioxide SO 2 and sulfur trioxide SO 3 (collectively often referred to as SO x ).
  • the SO 2 is formed as a result of the combustion of sulfur containing fuels such as high sulfur coal.
  • the SO 3 is formed by oxidation of the SO 2 for example when oxygen content in the flue gas is too high or when the flue gas temperature is too high (e.g., greater than 800° C.).
  • the SO 3 can form a liquid aerosol known as sulfuric acid (H 2 SO 4 ) mist that is very difficult to remove.
  • SCR Selective Catalytic Reduction
  • NO X nitrogen oxides
  • N 2 diatomic nitrogen
  • H 2 O water
  • Particulate control systems such as bag houses, wet Electro Static Precipitators (ESPs) and dry ESPs can be employed to remove particulate matter from the flue gas stream. Dry ESPs are more efficient and easier to maintain than wet ESPs, but dry ESPs require a drier flue gas stream than wet ESPs.
  • Creating a dry flue gas stream can be difficult because as the flue gas temperature decreases below the dew point of SO 3 at a cold-end of the APH, condensation can occur, thereby causing SO 3 to form H 2 SO 4 and a relatively wet flue gas. Moreover, if the flue gas contains the H 2 SO 4 mist, then the less efficient wet ESP is typically employed to remove the H 2 SO 4 . In addition, the ESPs tend to experience dust fouling (e.g., an undesirable accumulation of fly ash on ESP collector plates and removal troughs) when the temperature of the flue gas is high (e.g., 130° C. or greater).
  • dust fouling e.g., an undesirable accumulation of fly ash on ESP collector plates and removal troughs
  • FGD Flue Gas Desulfurization
  • the FGD systems are primarily directed to removing any SO 2 , for example, by the use of SO 2 absorbers.
  • Wet SO 2 absorbers typically spray water mixed with a sorbent on a stream of flue gas flowing through the SO 2 absorber to absorb the SO 2 from the flue gas.
  • the flue gas exiting the SO 2 absorber is saturated with water that contains some SO 2 .
  • One operational limitation of the FGD systems is the flue gas exiting the SO 2 absorber can be highly corrosive to any downstream equipment such as fans, ducts, and stacks.
  • Another operational limitation of the FGD systems is that the SO 2 absorbers require a substantial water supply and sorbent regeneration equipment.
  • One operational limitation relating to APH's is that employing heat transfer elements with increased heat transfer efficiency and area can cause the flue gas temperature to decrease below the dew point of SO 3 at which temperature, condensation at a cold-end of the APH can occur.
  • the SO 3 reacts with the water to form sulfuric acid H 2 SO 4 which condenses on the APH heat transfer elements.
  • the particulate matter can adhere to the condensed H 2 SO 4 causing fouling of the APH.
  • those skilled in the relevant art have been discouraged from reducing the component temperature and/or flue gas temperature exiting the APH to below the dew point of SO 3 and from further employing APH's with increased efficiency heat transfer elements and heat transfer area. This inability to completely realize the full potential of increasing the efficiency of the APH therefore limits the ability to increase the thermal efficiency of the steam generator system to be increased to its full potential.
  • the steam generator system 100 includes a steam generator vessel 101 that includes a flue gas outlet 101 B that is in communication with a Selective Catalytic Reduction (SCR) system 102 via an SCR inlet 102 A.
  • the SCR system 102 includes an SCR outlet 102 B that is in communication with an air preheater (APH) 103 via a first APH inlet 103 A.
  • An air supply line 103 D is in communication with a second APH inlet 103 C.
  • the APH 103 includes a first APH outlet 103 E that is in communication with an inlet 101 A to the steam generator vessel 101 .
  • the APH 103 includes a second APH outlet 103 B that is in communication with an inlet 104 A of an Electro Static Precipitator (ESP) 104 .
  • the ESP 104 includes an outlet 104 B that is in communication with an inlet 105 A of a fan 105 (e.g., an induced draft fan).
  • the fan 105 includes an outlet 105 B that is in communication with a hot side inlet 106 XA of a heat recovery section 106 X of a gas-to-gas heat exchanger (GGH).
  • the heat recovery section 106 X has a first outlet 106 XB that is in communication with an inlet 107 A of a Flue Gas Desulfurization (FGD) system 107 .
  • FGD Flue Gas Desulfurization
  • the FGD system 107 includes an outlet 107 B that is in communication with a cold side inlet 106 YA of a re-heating section 106 Y of the GGH.
  • the re-heating section 106 Y includes a second outlet 106 YB that is in communication with a fan inlet 108 A of a fan 108 .
  • the heat recovery section 106 X includes an inlet 106 XC that is in communication with an outlet 106 YD of the re-heating section 106 Y via a sealed conduit 106 Q for conveying a heat transfer medium therein.
  • the heat recovery section 106 X includes an outlet 106 XD that is in communication with an inlet 106 YC of the re-heating section 106 Y via sealed conduit 106 R for conveying the heat transfer medium therein.
  • the fan 108 includes an outlet 108 B that is in communication with an inlet 109 A of an exhaust stack 109 .
  • the exhaust stack 109 includes a stack outlet 109 B.
  • Operation of the steam generator system 100 involves supplying a fuel such as pulverized coal to the steam generator vessel 101 .
  • Air for combustion of the coal is provided via the air supply 103 D which is heated in the APH 103 via a stream of hot flue gas that is discharged from the steam generator vessel 101 after having been treated for NO X reduction in the SCR 102 .
  • Flue gas that is discharged from the APH outlet 103 B and supplied to the ESP 104 typically has a temperature of about 130° C. Operation of the ESP 104 at 130° C. tends to cause dust fouling in the ESP 104 , as described herein.
  • the temperature of the flue gas is reduced to about 90° C.
  • the fan 105 is required to increase the pressure of the flue gas to ensure continued flow at sufficient velocity through the GGH 106 and the FGD system 107 .
  • the desulfurization processing in the FGD system 107 reduces the temperature of the flue gas to about 50° C. as a result of contact the water in the FGD system 107 . Discharge of flue gas into the stack 109 at such low temperatures tends to cause corrosion problems and a visible plume at the discharge 109 B of the stack 109 .
  • the flue gas is recirculated back into the GGH 106 to reheat the flue gas to about 90° C. Recirculation of the flue gas back through the GGH 106 results in further pressure losses and the fan 108 is required to increase pressure and velocity of the flue gas to an acceptable magnitude.
  • Drawbacks of the steam generator system 100 include: 1) the reduction in overall thermal efficiency due to the power consumed by the fans 105 and 108 ; 2) the dust fouling problems in the ESP 104 due to the high temperature of the flue gas; 3) the less than optimum APH 103 which cannot employ heating elements having a greater efficiency and area; 4) the inability to employ a dry ESP because of the presence of sulfuric acid H 2 SO 4 in the flue gas; and 5) inefficiencies of the FGD 107 due to the high SO 3 concentration of greater than 5 ppm in the flue gas.
  • FIG. 2 another prior art steam generator system 101 ′ is similar, in some regards, to the prior art steam generator system 100 of FIG. 1 .
  • similar components are designated with similar reference characters followed by a prime designation.
  • the prior art steam generator system 100 ′ includes a steam generator vessel 101 ′ that includes a flue gas outlet 101 B′ that is in communication with a Selective Catalytic Reduction (SCR) system 102 ′ via an SCR inlet 102 A′.
  • the SCR system 102 ′ includes an SCR outlet 102 B′ that is in communication with an air preheater (APH) 103 ′ via a first APH inlet 103 A′.
  • An air supply line 103 D′ is in communication with a second APH inlet 103 C′.
  • the APH 103 ′ includes a first APH outlet 103 E′ that is in communication with an inlet 101 A′ to the steam generator vessel 101 ′.
  • the APH includes a second APH outlet 103 B′ that is in communication with a hot side inlet 106 XA′ of a heat recovery section 106 X′ of a gas-to-gas heat exchanger GGH.
  • the heat recovery section 106 X′ has a first outlet 106 XB′ that is in communication with an inlet 104 A′ of an Electro Static Precipitator (ESP) 104 ′.
  • the ESP 104 ′ includes an outlet 104 B′ that is in communication with an inlet 105 A′ of a fan 105 ′ (e.g., an induced draft fan).
  • the fan 105 ′ includes an outlet 105 B′ that is in communication with an inlet 107 A′ of a Flue Gas Desulfurization (FGD) system 107 ′.
  • the FGD system 107 ′ includes an outlet 107 B′ that is in communication with a cold side inlet 106 YA′ of a re-heating section 106 Y′ of the GGH.
  • the re-heating section 106 Y′ includes an outlet 106 YB′ that is in communication with a fan inlet 108 A′ of a fan 108 ′.
  • the heat recovery section 106 X′ includes an inlet 106 XC′ that is in communication with an outlet 106 YD′ of the re-heating section 106 Y′ via a sealed conduit 106 Q′ for conveying a heat transfer medium therein.
  • the heat recovery section 106 X′ includes an outlet 106 XD′ that is in communication with an inlet 106 YC′ of the re-heating section 106 Y′ via sealed conduit 106 R′ for conveying the heat transfer medium therein.
  • the fan 108 ′ includes an outlet 108 B′ that is in communication with an inlet 109 A′ of an exhaust stack 109 ′.
  • the exhaust stack 109 ′ includes a stack outlet 109 B′.
  • the steam generator system 101 ′ differs from the steam generator system 101 in that the GGH 106 is positioned between the APH 103 ′ and the ESP 104 in an effort to raise the temperature of the flue gas to 90° C. before entering the ESP 104 ′. While the steam generator system 101 ′ attempts to improve the operation of the ESP 104 ′, the other drawbacks of the steam generator system 101 remain.
  • the method includes providing a steam generator system having a steam generator vessel, an air supply system, an air preheater, a particulate removal system (e.g., a dry electro static precipitator and/or a fabric filter), a flue gas desulfurization system, and a flue gas discharge stack.
  • the air supply system is in communication with the steam generator vessel through the air preheater.
  • the steam generator vessel is in communication with the discharge stack through the air preheater, the particulate removal system and the flue gas desulfurization system.
  • the particulate removal system is located downstream of the air preheater.
  • the flue gas desulfurization system is located downstream of the particulate removal system and the discharge stack is located downstream of the flue gas desulfurization system.
  • the method includes having the air supply system provide a first amount of air to the air preheater.
  • the first amount of air is of a magnitude in excess of that required for combustion of fuel in the steam generator vessel.
  • the method includes having the air preheater provide the first amount of air at a mass flow sufficient to establish a first temperature of a flue gas mixture exiting the air preheater.
  • the first temperature is of a magnitude such that the air preheater has a cold end metal temperature that is no less than a water dew point temperature in the air preheater and such that the cold end metal temperature is less than a sulfuric acid dew point temperature.
  • the first temperature is from about 105° C. (220° F.) to about 125° C. (257° F.).
  • the method includes mitigating SO 3 in the flue gas mixture generated in the steam generator vessel. The mitigating of SO 3 occurs before the flue gas mixture enters the air preheater.
  • the method includes configuring the air preheater to heat the first amount of air to a second temperature of about 288° C. to 399° C. (550° F. to 750° F.).
  • the method also includes supplying a first portion of the first amount of air as combustion air to the steam generator vessel for combustion of the fuel.
  • the flue gas mixture is discharged at the first temperature, directly from the air preheater to the particulate removal system thereby removing particulate from the flue gas mixture and creating a first treated flue gas mixture.
  • the method further includes discharging the first treated flue gas mixture from the particulate removal system directly into the flue gas desulfurization system thereby creating in and discharging from the flue gas desulfurization system, a second treated flue gas mixture at a third temperature, for example, but not limited to 52° C. to about 60° C. (125° F. to 140° F.).
  • the third temperature is of a magnitude sufficient to inject a second portion of the first amount of air as flue gas reheat air fed from the air preheater at the second temperature with the second flue treated flue gas mixture at the third temperature thereby creating third treated flue gas mixture at a fourth temperature (e.g., at least about 68° C. (155° F.)), prior to entering the discharge stack.
  • the third temperature is of a magnitude sufficient to allow the flue gas reheat air to raise the fourth temperature to a magnitude sufficient to mitigate visible plume exiting the discharge stack and to mitigate corrosion in the discharge stack.
  • the method includes admitting the third treated flue gas mixture to the discharge stack at the fourth temperature.
  • the steam generator system further includes a selective catalytic reduction system and the steam generator vessel is in communication with the air preheater through the selective catalytic reduction system.
  • the steam generator system further includes a flue gas reheat air particulate removal system and the air preheater is in communication with the discharge stack through the flue gas reheat air particulate removal system.
  • the flue gas reheat air particulate removal system removes particulate contaminants from the second portion of air that are introduced to the second portion of air from leakage within the air preheater from the flue gas mixture.
  • the steam generator system further includes a humidity sensor disposed between the steam generator vessel and the air preheater and the method includes measuring, with the humidity sensor, the humidity of the flue gas mixture to determine a magnitude of first temperature.
  • the steam generator system further includes an infrared sensor and the method includes determining, with the infrared sensor, the cold end metal temperature in the air preheater; comparing the cold end metal temperature to the water dew point temperature; and controlling the cold end metal temperature to be no less than the water dew point temperature.
  • the mitigating of SO 3 in the flue gas mixture includes supplying a low sulfur fuel to the steam generator vessel, wherein the low sulfur fuel generates less than 5 parts per million SO 3 .
  • the mitigating SO 3 in the flue gas mixture includes removing SO 3 in the flue gas mixture prior to admitting the flue gas mixture to the air preheater.
  • the mitigating SO 3 in the flue gas mixture includes chemically rendering the SO 3 in the flue gas mixture into an inert salt, prior to admitting the flue gas mixture to the air preheater.
  • the chemically rendering may include spraying an aqueous suspension of a reagent containing sodium, magnesium, potassium, ammonium and/or calcium thiosulfate and containing a soluble salt compound such as one or more of thiosulfate and chloride species to create a particulate mist containing dry particles of at least one soluble salt compound that can react with the SO 3 in the flue gas.
  • the method includes further providing an injection device (e.g., a duct manifold) between the flue gas desulfurization system and the discharge stack and wherein the injecting of the second portion of the first amount of air, at the second temperature, with the second flue treated flue gas mixture at the third temperature occurs in the injection device.
  • an injection device e.g., a duct manifold
  • the injection device includes the duct manifold positioned between the flue gas desulfurization system and the discharge stack.
  • the duct manifold has an inlet for receiving the second treated flue gas mixture, a branch connection for receiving the second portion of the first amount of air and an outlet in communication with the discharge stack.
  • the injection device includes a mixer, turning vanes, and/or a tabulator device.
  • the discharging the flue gas mixture at the first temperature, directly from the air preheater to the particulate removal system, is accomplished with no heat exchangers disposed between the air preheater and the particulate removal system.
  • the discharging the first treated flue gas mixture from the particulate removal system directly into the flue gas desulfurization system is accomplished with no heat exchangers disposed between the particulate removal system and the flue gas desulfurization system.
  • the injection of the second portion of the first amount of air is conducted at a mass ratio of the second portion to the second treated flue gas mixture of 1 percent to 16 percent. In one embodiment, the injection of the second portion of the first amount of air is conducted at a mass ratio of the second portion to the second treated flue gas mixture of 9 percent to 16 percent.
  • the system includes a steam generator vessel, an air preheater in communication with the steam generator vessel, an air supply system configured to provide air to the steam generator vessel through the air preheater, a particulate removal system (e.g., a dry electro static precipitator and/or a fabric filter), a flue gas desulfurization system and a discharge stack.
  • the steam generator vessel is in communication with the discharge stack through the air preheater, the particulate removal system and the flue gas desulfurization system.
  • the particulate removal system is located directly downstream of the air preheater.
  • the flue gas desulfurization system is located directly downstream of the particulate removal system.
  • the discharge stack is located directly downstream of the flue gas desulfurization system.
  • the air supply system is configured to provide a first amount of air to the air preheater.
  • the first amount of air is of a magnitude in excess of that required for combustion of fuel in the steam generator vessel.
  • the air preheater is configured to provide the first amount of air at a mass flow sufficient to establish a first temperature of a flue gas mixture exiting the air preheater.
  • the first temperature is of a magnitude such that the air preheater has a cold end metal temperature that is no less than a water dew point temperature in the air preheater and such that the cold end metal temperature is less than a sulfuric acid dew point temperature.
  • the first temperature is from about 105° C. (220° F.
  • the system includes SO 3 mitigation upstream of the air preheater, the SO 3 mitigation is configured to mitigate SO 3 in the flue gas mixture generated in the steam generator vessel.
  • the air preheater is configured to heat the first amount of air to a second temperature of about 288° C. to 399° C. (550° F. to 750° F.).
  • the particulate removal system is configured to convey the flue gas mixture at a third temperature, for example, but not limited to 52° C. to about 60° C. (125° F. to 140° F.), directly to the flue gas desulfurization system.
  • An excess air duct is in communication with the air preheater.
  • a second duct is positioned between the flue gas desulfurization system and the discharge stack.
  • the excess air duct is configured to convey a second portion of the first amount of air as flue gas reheat air fed from the air preheater at the second temperature from the air preheater to the second duct.
  • the system includes an injection device (e.g., a duct manifold) located between the flue gas desulfurization system and the discharge stack.
  • the injection device is configured to discharge the flue gas into the discharge stack at a fourth temperature (e.g., at least about 68° C. (155° F.)).
  • the third temperature is of a magnitude sufficient to allow the flue gas reheat air to raise the fourth temperature to a magnitude sufficient to mitigate visible plume exiting the discharge stack and to mitigate corrosion in the discharge stack.
  • the steam generator system further includes a selective catalytic reduction system and the steam generator vessel is in communication with the air preheater through the selective catalytic reduction system.
  • the steam generator system further includes a flue gas reheat air particulate removal system and the air preheater is in communication with the discharge stack through the flue gas reheat air particulate removal system operatively to remove from the second portion of air particulate contaminants introduced from leakage within the air preheater from the flue gas mixture.
  • the steam generator system further comprises a humidity sensor disposed in the communication between the steam generator vessel and the air preheater to measure humidity of the flue gas mixture and with the humidity sensor being used to determine the magnitude of first temperature.
  • the steam generator system further comprises an infrared sensor to determine the air preheater temperature and a control unit configured to control the cold end metal temperature above the water dew point in the air preheater.
  • the SO 3 mitigation includes supplying a low sulfur fuel to the steam generator vessel.
  • the low sulfur fuel generates less than 5 parts per million SO 3 .
  • the SO 3 mitigation includes removing SO 3 in the flue gas mixture prior to admitting the flue gas mixture to the air preheater.
  • the SO 3 mitigation includes chemically rendering the SO 3 in the flue gas mixture into an inert salt, prior to admitting the flue gas mixture to the air preheater.
  • the chemically rendering may include spraying an aqueous suspension of a reagent containing sodium, magnesium, potassium, ammonium and/or calcium thiosulfate and containing one or more soluble salt compounds such as thiosulfate and chloride species to create a particulate mist containing dry particles of at least one soluble salt compound that can react with the SO 3 in the flue gas.
  • the system is configured with no fans disposed between the flue gas desulfurization system and the discharge stack.
  • the system is configured with no heat exchangers disposed between the air preheater and the flue gas desulfurization system.
  • the system is configured with no fans disposed between the flue gas reheat air particulate removal system and the discharge stack.
  • the method includes removing one or more heat exchangers positioned downstream of the air preheater and reconfiguring an air supply source to the air preheater to supply a first amount of air in excess of that required for combustion of fuel in the steam generator vessel.
  • the method also includes reconfiguring one or more of the air supply source and the air preheater such that the first amount of air is provided at a mass flow sufficient to establish a first temperature of a flue gas mixture exiting the air preheater.
  • the first temperature is of a magnitude such that the air preheater has a cold end metal temperature that is no less than a water dew point temperature in the air preheater and such that the cold end metal temperature is less than a sulfuric acid dew point temperature.
  • the first temperature is from about 105° C. (220° F.) to about 125° C. (257° F.).
  • the method includes providing SO 3 mitigation in communication with the steam generator vessel.
  • the SO 3 mitigation is configured to mitigate the SO 3 in the flue gas mixture generated in the steam generator vessel. The mitigating of SO 3 occurs before the flue gas mixture enters the air preheater.
  • the method includes configuring the air preheater to heat the first amount of air to a second temperature which is substantially no less than the temperature of combustion air of an original system and being about of 288° C. to 399° C. (550° F. to 750° F.) to maintain or improve boiler efficiency.
  • the method includes supplying a first portion of the first amount of air to the steam generator vessel for combustion of the fuel.
  • the method further includes discharging the flue gas mixture at the first temperature, directly from the air preheater to the particulate collection system, thereby removing particulate from the flue gas mixture and creating a first treated flue gas mixture.
  • the method also includes, discharging the first treated flue gas mixture from the particulate removal system directly into the flue gas desulfurization system thereby creating in and discharging from the flue gas desulfurization system, a second treated flue gas mixture at a third temperature, for example, but not limited to 52° C. to about 60° C. (125° F. to 140° F.).
  • the method includes injecting a second portion of the first amount of air as flue gas reheat air fed from the air preheater at the second temperature with the second flue treated flue gas mixture at the third temperature, thereby creating third treated flue gas mixture at a fourth temperature (e.g., at least about 68° C. (155° F.)), prior to entering the discharge stack.
  • a fourth temperature e.g., at least about 68° C. (155° F.
  • the method also includes, admitting the third treated flue gas mixture to the discharge stack at the fourth temperature.
  • the third temperature is of a magnitude sufficient to allow the flue gas reheat air to raise the fourth temperature to a magnitude sufficient to mitigate visible plume exiting the discharge stack and to mitigate corrosion in the discharge stack.
  • the retrofit method includes replacing at least a portion of an outlet duct connecting the flue gas desulfurization system and the discharge stack with a manifold that connects the flue gas desulfurization system, an excess air duct and the discharge stack.
  • the steam generator system further includes a flue gas reheat air particulate removal system, and the air preheater is in communication with the discharge stack through the flue gas reheat air particulate removal system.
  • the retrofit method includes removing particulate contaminants from the second portion of air, the particulate contaminants being introduced to the second portion of air from leakage within the air preheater from the flue gas mixture.
  • the steam generator system further includes a humidity sensor disposed in the communication between the steam generator vessel and the air preheater and the retrofit method includes measuring, with the humidity sensor, humidity of the flue gas mixture to determine a magnitude of first temperature.
  • the steam generator system further includes an infrared sensor and the retrofit method includes determining, with the infrared sensor, the cold end metal temperature in the air preheater, comparing the cold end metal temperature to the water dew point temperature; and controlling the cold end metal temperature to be no less than the water dew point temperature.
  • a second thermal efficiency of the steam generator system, after implementing the retrofit method is at least as great as a first thermal efficiency of the steam generator system before implementing the retrofit method.
  • the method includes providing a steam generator system that includes a steam generator vessel, an air supply system, an air preheater, a first particulate removal system, a second particulate removal system, a flue gas desulfurization system, and a flue gas discharge stack.
  • the air supply system is in communication with the steam generator vessel through the air preheater and the steam generator vessel is in communication with the discharge stack through the air preheater, the first particulate removal system and the flue gas desulfurization system.
  • the first particulate removal system is located downstream of the air preheater and the flue gas desulfurization system is located downstream of the first particulate removal system.
  • the discharge stack is located downstream of the flue gas desulfurization system and the air preheater is in communication with the discharge stack through the second particulate removal system.
  • the method also includes providing a humidity sensor disposed between the steam generator vessel and the air preheater; and providing an infrared sensor in the air preheater.
  • the method includes humidity of a flue gas mixture with the humidity sensor to determine a magnitude of a first temperature.
  • the air supply system provides a first amount of air to the air preheater.
  • the first amount of air is of a magnitude in excess of that required for combustion of fuel in the steam generator vessel.
  • the air preheater provides the first amount of air at a mass flow sufficient to establish a first temperature of a flue gas mixture exiting the air preheater.
  • the first temperature is of a magnitude such that the air preheater has a cold end metal temperature that is no less than a water dew point temperature in the air preheater and such that the cold end metal temperature is less than a sulfuric acid dew point temperature.
  • the first temperature is from about 105° C. (220° F.) to about 125° C. (257° F.).
  • the method includes determining, with the infrared sensor, the cold end metal temperature in the air preheater, comparing the cold end metal temperature to the water dew point temperature; and controlling the cold end metal temperature to be no less than the water dew point temperature.
  • the method includes mitigating SO 3 in the flue gas mixture generated in the steam generator vessel.
  • the mitigating of SO 3 occurs before the flue gas mixture enters the air preheater.
  • the method includes configuring the air preheater to heat the first amount of air to a second temperature of about 288° C. to 399° C. (550° F. to 750° F.) and supplying a first portion of the first amount of air as combustion air to the steam generator vessel for combustion of the fuel.
  • the method includes discharging the flue gas mixture at the first temperature, directly from the air preheater to the particulate removal system, thereby removing particulate from the flue gas mixture and creating a first treated flue gas mixture.
  • the method includes discharging the first treated flue gas mixture from the particulate removal system directly into the flue gas desulfurization system thereby creating in and discharging from the flue gas desulfurization system, a second treated flue gas mixture at a third temperature of 52° C. to 60° C. (125° F. to 140° F.).
  • the method includes removing particulate contaminants from the second portion of air. The particulate contaminants are introduced to the second portion of air from leakage within the air preheater from the flue gas mixture.
  • the method further includes injecting a second portion of the first amount of air as flue gas reheat air fed from the air preheater at the second temperature with the second flue treated flue gas mixture at the third temperature, thereby creating third treated flue gas mixture at a fourth temperature of at least 68° C. (155° F.), prior to entering the discharge stack.
  • the method also includes admitting the third treated flue gas mixture to the discharge stack at the fourth temperature.
  • FIG. 1 is a schematic flow diagram of a prior art steam generator system
  • FIG. 2 is a schematic flow diagram of another prior art steam generator system
  • FIG. 3 is a schematic flow diagram of a steam generator system of the present invention.
  • FIG. 4 is a schematic flow diagram if another embodiment of the steam generator system of the present invention.
  • FIG. 5 is a graph of reheat air ratio to scrubbed gas for various flue gas temperature increases.
  • FIG. 6 is a graph of air preheater efficiency improvements.
  • the steam generator system 10 includes a steam generator vessel 11 and an air preheater 13 (e.g., a rotary regenerative heat exchanger).
  • the air preheater 13 is in communication with the steam generator vessel 11 via a duct 63 .
  • the steam generator system 10 includes an air supply system 13 D configured to provide air to the steam generator 11 through the air preheater 13 .
  • the steam generator system 10 also includes a particulate removal system 14 , a flue gas desulfurization system 17 and a discharge stack 19 in the configuration illustrated in FIG. 3 .
  • the term “improving the effectiveness of a steam generator system” includes: 1) maintaining the overall thermal efficiency of the steam generator system 10 while eliminating heat exchangers between the air preheater 13 and the discharge stack 19 ; 2) reducing fouling in the air preheater 13 ; 3) improving the efficiency of the particle removal system 14 ; 4) improving the efficiency of the air preheater 13 and/or 5) improving the overall thermal efficiency of the steam generator system 10 compared to prior art steam generator systems (e.g., the steam generator systems 100 and 100 ′ of FIGS. 1 and 2 ).
  • the steam generator vessel 11 is in communication with the discharge stack 19 through the air preheater 13 ; the particulate removal system 14 and the flue gas desulfurization system 17 .
  • the particulate removal system 14 is located directly downstream of the air preheater 13 , such that there are no other substantive components such as fans or heat exchangers located between the air preheater 13 and the particulate removal system 14 which are in fluid communication with one another via a duct 60 .
  • there is no GGH 106 X′ similar to that shown in FIG. 2 , located between the air preheater 13 and the particulate removal system 14 .
  • the flue gas desulfurization system 17 is located directly downstream of the particulate removal system 14 , such that there are no other substantive components, such as heat exchangers, located between the particulate removal system 14 and the flue gas desulfurization system 17 which are in fluid communication with one another via a duct 61 .
  • the discharge stack 19 is located directly downstream of the flue gas desulfurization system 17 , such that there are no other substantive components such as fans or heat exchangers located between the flue gas desulfurization system 17 and the discharge stack 19 which are in fluid communication with one another via a duct 62 .
  • the duct 62 includes a reheat air injection device 21 , such as a mixer, one or more turning vanes, a juncture and/or a tabulator device disposed therein for mixing of a second portion P 2 of the first amount A 1 of air with a second treated flue gas mixture FG 2 , as described herein.
  • a reheat air injection device 21 such as a mixer, one or more turning vanes, a juncture and/or a tabulator device disposed therein for mixing of a second portion P 2 of the first amount A 1 of air with a second treated flue gas mixture FG 2 , as described herein.
  • the air supply system 13 D is configured to provide a first amount A 1 of air to the air preheater 13 .
  • the first amount A 1 of air is of a magnitude in excess of that required for combustion of fuel in the steam generator vessel 11 .
  • the air preheater 13 is configured to provide the first amount A 1 of air at a mass flow sufficient to establish a first temperature T 1 of a flue gas mixture FG exiting the air preheater 13 .
  • the first temperature T 1 is such that the air preheater 13 has a cold end metal temperature that is no less than a water dew point temperature in the air preheater 13 and such that the cold end metal temperature is less than a sulfuric acid dew point temperature.
  • the term “cold end metal” as used herein is the portion of the air preheater 13 that is at the lowest temperature in therein.
  • the first temperature T 1 is from about 105° C. (220° F.) to about 125° C. (257° F.).
  • the air preheater 13 is also configured to heat the first amount of air A 1 to a second temperature T 2 of about 288° C. to 399° C. (550° F. to 750° F.) for use in combustion of the fuel and for reheat air as described herein.
  • the steam generator system 10 includes one or more systems or devices for SO 3 mitigation upstream of the air preheater 13 which are configured to mitigate SO 3 in the flue gas mixture FG generated in the steam generator vessel 11 .
  • one or more systems or devices for SO 3 mitigation upstream of the air preheater 13 includes supplying a low sulfur fuel to the steam generator vessel 11 .
  • the low sulfur fuel has a composition suitable for generating less than 5 parts per million SO 3 .
  • the one or more systems or devices for SO 3 mitigation upstream of the air preheater 13 includes removing SO 3 in the flue gas mixture FG prior to admitting the flue gas mixture FG to the air preheater 13 , for example in the duct 63 .
  • the one or more systems or devices for SO 3 mitigation upstream of the air preheater 13 includes chemically rendering the SO 3 in the flue gas mixture into an inert salt, prior to admitting the flue gas mixture FG to the air preheater 13 .
  • the chemically rendering includes spraying an aqueous suspension of a reagent containing sodium, magnesium, potassium, ammonium and/or calcium thiosulfate and containing one or more soluble salt compounds such as thiosulfate and chloride species to create a particulate mist containing dry particles of at least one soluble salt compound that can react with the SO 3 in the flue gas.
  • the particulate removal system 14 is configured to convey the flue gas mixture FG 2 at a third temperature T 3 of 52° C. to 60° C. (125° F. to 140° F.) directly to the flue gas desulfurization system 17 , via the duct 61 .
  • the particulate removal system 14 is a dry Electro Static Precipitator (ESP).
  • ESP Electro Static Precipitator
  • Such a dry ESP includes rows of thin vertical wires (not shown) followed by a stack of large flat metal plates (not shown) oriented vertically.
  • the flue gas FG flows horizontally through spaces between the wires, and then passes through the stack of plates. A negative voltage of several thousand volts is applied between wires and plates.
  • an electric corona discharge ionizes the flue gas around the electrodes, which then ionizes the particles in the flue gas stream.
  • the ionized particles due to the electrostatic force, are diverted towards the grounded plates. Particles build up on the collection plates and are removed therefrom.
  • the steam generator system 10 ′ further comprises a flue gas reheat air particulate removal system 33 positioned in and between ducts 64 and 65 .
  • the air preheater 13 is in communication with the discharge stack 19 through the flue gas reheat air particulate removal system 33 to operatively remove, from the second portion P 2 of air, particulate contaminants introduced from leakage within the air preheater 13 from the flue gas mixture FG.
  • the flue gas reheat air particulate removal system 33 is configured similar to the particulate removal system 14 as described herein. As illustrated in FIG. 4 , there are no fans disposed between the flue gas reheat air particulate removal system 33 and the discharge stack 19 .
  • an excess air duct 65 is in communication with the air preheater 13 and the duct 62 positioned between the flue gas desulfurization system 17 and the discharge stack 19 .
  • the excess air duct 65 is configured to convey a second portion P 2 of the first amount A 1 of air as flue gas reheat air P 2 fed from the air preheater 13 at the second temperature T 2 from the air preheater 13 to the second duct 62 .
  • the excess air duct 65 is covered with a thermal insulation (not shown) in order to minimize heat loss from the excess air duct 65 .
  • the excess air duct 65 is configured with a suitable cross sectional flow area, smooth internal surfaces and a minimal number of bends to minimize pressure loss through the excess air duct 65 .
  • a reheat air injection device 21 is located between the flue gas desulfurization system 17 and the discharge stack 19 .
  • the reheat air injection device 21 is configured to discharge the flue gas into the discharge stack 19 at a fourth temperature T 4 of at least 68° C. (155° F.).
  • the reheat air injection device 21 includes a mixer, one or more turning vanes, a juncture and/or a tabulator device disposed therein for mixing of the second portion P 2 (i.e., the flue gas reheat air P 2 ) of the first amount A 1 of air with the second treated flue gas mixture FG 2 .
  • the reheat air injection device is part of a manifold 39 that connects the flue gas desulfurization system 17 the excess air duct 65 and the discharge stack 19 .
  • the manifold includes a branch connection to which the excess air duct 65 is connected.
  • the steam generator system 10 ′ includes a selective catalytic reduction system (SCR) 31 for converting nitrogen oxides, also referred to as NO X with the aid of a catalyst into diatomic nitrogen (N 2 ) and water (H 2 O).
  • SCR selective catalytic reduction system
  • the steam generator vessel 11 is in communication with the air preheater 13 through the SCR 31 .
  • the steam generator system 10 ′ includes a humidity sensor 34 disposed in an outlet of the steam generator vessel 11 and upstream of the air preheater 13 to measure humidity of the flue gas mixture FG 1 .
  • the humidity sensor is configured to determine the magnitude of first temperature T 1 .
  • the steam generator system 10 ′ includes an infrared sensor 32 to determine the air preheater temperature.
  • the infrared sensor 32 is configured to determine the air preheater temperature for example, the cold end metal temperature, by measuring the temperature of a portion of the air preheater 13 that is in thermal communication with or proximate to the cold end.
  • the steam generator system 10 ′ includes a control unit 71 , such as a computer processor, memory and signal processing electronics configured to control the cold end metal temperature above the water dew point in the air preheater 13 .
  • the present invention includes a method for improving effectiveness of a steam generator system 10 .
  • the method includes providing a steam generator system 10 as described in detail herein and including the steam generator vessel 11 , the air supply system 13 D, the air preheater 13 , the particulate removal system 14 , the flue gas desulfurization system 17 , and the flue gas discharge stack 19
  • the air supply system 13 D is in communication with the steam generator vessel 11 through the air preheater 13 , and with the steam generator vessel 11 being in communication with the discharge stack 19 through the air preheater 13 , the particulate removal system 14 and the flue gas desulfurization system 17 .
  • the particulate removal system 14 is located downstream of the air preheater 13 .
  • the flue gas desulfurization system 17 is located downstream of the particulate removal system 14 .
  • the discharge stack 19 is located downstream of the flue gas desulfurization system 17 .
  • the method includes having the air supply system 13 D provide the first amount A 1 of air to the air preheater 13 .
  • the first amount A 1 of air is of a magnitude in excess of that required for combustion of fuel in the steam generator vessel 11 .
  • the air preheater 13 provides the first amount A 1 of air at a mass flow sufficient to establish a first temperature T 1 of a flue gas mixture FG exiting the air preheater 13 .
  • the first temperature T 1 is such that the air preheater has a cold end metal temperature that is no less than a water dew point temperature in the air preheater 13 and such that the cold end metal temperature is less than a sulfuric acid dew point temperature.
  • the first temperature T 1 being from about 105° C. (220° F.) to about 125° C. (257° F.).
  • the method includes mitigating SO 3 in the flue gas mixture FG generated in the steam generator vessel 11 , before the flue gas mixture FG enters the air preheater 13 .
  • the method includes configuring the air preheater 13 to heat the first amount of air A 1 to a second temperature T 2 of about 288° C. to 399° C. (550° F. to 750° F.) and supplying a first portion P 1 of the first amount A 1 of air as combustion air to the steam generator vessel 11 for combustion of the fuel.
  • the method includes discharging the flue gas mixture FG at the first temperature T 1 , directly from the air preheater 13 to the particulate removal system 14 thereby removing particulate from the flue gas mixture FG and creating a first treated flue gas mixture FG 1 .
  • the method further includes discharging the first treated flue gas mixture FG 1 from the particulate removal system 14 directly into the flue gas desulfurization system 17 thereby creating in and discharging from the flue gas desulfurization system 17 , a second treated flue gas mixture FG 2 at a third temperature T 3 of 52° C. to 60° C. 125° F. to 140° F.
  • the method also includes injecting a second portion P 2 of the first amount A 1 of air as flue gas reheat air fed from the air preheater 13 at the second temperature T 2 with the second flue treated flue gas mixture FG 2 at the third temperature T 3 thereby creating third treated flue gas mixture FG 3 at a fourth temperature T 4 of at least 68° C. 155° F., prior to entering the discharge stack 19 .
  • the third treated flue gas mixture FG 3 is admitted to the discharge stack 19 at the fourth temperature T 4 .
  • the steam generator system 10 further includes an SCR 31 as shown in FIG. 4 for 31 for converting nitrogen oxides, also referred to as NO X with the aid of a catalyst into diatomic nitrogen (N 2 ) and water (H 2 O).
  • the steam generator vessel 11 is in communication with the air preheater 13 through the SCR 31 .
  • the steam generator system 10 ′ includes a flue gas reheat air particulate removal system 33 .
  • the air preheater 13 is in communication with the discharge stack 19 through the flue gas reheat air particulate removal system 33 .
  • the method includes removing particulate contaminants from the second portion P 2 of air. The particulate contaminants are introduced to the second portion P 2 of air from leakage within the air preheater 13 from the flue gas mixture FG 1 .
  • the steam generator system 10 ′ includes a humidity sensor 34 disposed between the steam generator vessel 11 and the air preheater 13 .
  • the method includes measuring, with the humidity sensor 34 , humidity of the flue gas mixture FG 1 to determine a magnitude of first temperature T 1 .
  • the steam generator system 10 ′ includes an infrared sensor 32 .
  • the method includes determining, with the infrared sensor, the cold end metal temperature in the air preheater 13 .
  • the infrared sensor 32 is determines the air preheater temperature for example, the cold end metal temperature, by measuring the temperature of a portion of the air preheater 13 that is in thermal communication with or proximate to the cold end.
  • the steam generator system 10 ′ includes a control unit 71 , such as a computer processor, memory and signal processing electronics and the method includes comparing the cold end metal temperature to the water dew point temperature and controlling, with the control unit, the cold end metal temperature above the water dew point in the air preheater 13 .
  • a control unit 71 such as a computer processor, memory and signal processing electronics and the method includes comparing the cold end metal temperature to the water dew point temperature and controlling, with the control unit, the cold end metal temperature above the water dew point in the air preheater 13 .
  • the method includes mitigating SO 3 in the flue gas mixture FG by supplying a low sulfur fuel to the steam generator vessel 11 .
  • the low sulfur fuel being of a composition to generate less than 5 parts per million SO 3 .
  • the method includes mitigating SO 3 in the flue gas mixture FG by removing SO 3 in the flue gas mixture FG prior to admitting the flue gas mixture FG to the air preheater 13 .
  • the method includes mitigating SO 3 in the flue gas mixture FG by chemically rendering the SO 3 in the flue gas mixture into an inert salt, prior to admitting the flue gas mixture FG to the air preheater 13 .
  • the chemically rendering step includes spraying an aqueous suspension of a reagent containing at least one of sodium, magnesium, potassium, ammonium and calcium thiosulfate and containing at least one soluble salt compound chosen from the group consisting of thiosulfate and chloride species to create a particulate mist containing dry particles of at least one soluble salt compound that can react with the SO 3 in the flue gas.
  • the method includes providing an injection device 21 between the flue gas desulfurization system 17 and the discharge stack 19 and wherein the injecting of the second portion P 2 of the first amount A 1 of air, at the second temperature T 2 , with the second flue treated flue gas mixture FG 2 at the third temperature T 3 occurs in the injection means.
  • the method includes the discharging the flue gas mixture FG at the first temperature T 1 , directly from the air preheater to the particulate removal system 14 with no heat exchangers disposed between the air preheater 13 and the particulate removal system 14 .
  • the method includes discharging the first treated flue gas mixture FG 1 from the particulate removal system 14 directly into the flue gas desulfurization system 17 , with no heat exchangers disposed between the particulate removal system 14 and the flue gas desulfurization system 17 .
  • the method includes injection of the second portion P 2 of the first amount A 1 of air at a mass ratio of the second portion P 2 to the second treated flue gas mixture FG 3 of 1 percent to 16 percent. In one embodiment, the method includes injection of the second portion P 2 of the first amount A 1 of air at a mass ratio of the second portion P 2 to the second treated flue gas mixture FG 3 of 9 percent to 16 percent.
  • the present invention includes a method for retrofitting a steam generator system 100 , 100 ′ for improved effectiveness.
  • the method for retrofitting includes removing one or more heat exchangers positioned downstream of the air preheater 13 .
  • the method for retrofitting includes reconfiguring an air supply source 13 D to the air preheater 13 to supply a first amount A 1 of air in excess of that required for combustion of fuel in the steam generator vessel 11 and reconfiguring at least one of the air supply source 13 D and the air preheater 13 the air preheater 13 such that the first amount A 1 of air is provided at a mass flow sufficient to establish a first temperature T 1 of a flue gas mixture FG exiting the air preheater 13 , the first temperature T 1 being such that the air preheater has a cold end metal temperature that is no less than a water dew point temperature in the air preheater 13 and such that the cold end metal temperature is less than a sulfuric acid dew point temperature, and the first temperature T 1 being from about 105°
  • the reconfiguring of the air supply 13 D includes but is not limited to employing a higher flow and/or pressure capacity fan or blower and/or reducing the pressure drop in the air supply system, compared to that employed in the prior art air supply 103 D, 103 D′ as shown in FIGS. 1 ′ and 2 , respectively.
  • the method for retrofitting includes providing one or more SO 3 mitigation systems in communication with the steam generator vessel 11 .
  • the SO 3 mitigation systems are configured to mitigate the SO 3 in the flue gas mixture generated in the steam generator vessel 11 .
  • the mitigating of SO 3 occurs before the flue gas mixture FG enters the air preheater 13 .
  • the method for retrofitting includes configuring the air preheater 13 to heat the first amount of air A 1 to a second temperature T 2 .
  • the second temperature is substantially no less than the temperature of combustion air of an original system (e.g., a prior art steam generator system 100 , 100 ′ of FIGS. 1 and 2 , respectively). In one embodiment, the second temperature is about of 288° C. to 399° C. (550° F.
  • the method for retrofitting includes supplying a first portion P 1 of the first amount A 1 of air to the steam generator vessel 11 for combustion of the fuel.
  • the method for retrofitting includes discharging the flue gas mixture FG at the first temperature T 1 , directly from the air preheater 13 to the particulate collection system 14 thereby removing particulate from the flue gas mixture FG and creating a first treated flue gas mixture FG 1 .
  • the first treated flue gas mixture FG 1 is discharged from the particulate removal system 14 directly into the flue gas desulfurization system 17 (i.e., without flowing through a heat exchanger such as the GGH 106 Y, 106 Y′ of the prior art heat exchanger systems of FIGS. 1 and 2 , respectively).
  • the method for retrofitting includes creating in and discharging from the flue gas desulfurization system 17 , a second treated flue gas mixture FG 2 at a third temperature T 3 of 52° C. to 60° C. (125° F. to 140° F.).
  • the method for retrofitting includes injecting a second portion P 2 of the first amount A 1 of air as flue gas reheat air fed from the air preheater 13 at the second temperature T 2 with the second flue treated flue gas mixture FG 2 at the third temperature T 3 thereby creating third treated flue gas mixture FG 3 at a fourth temperature T 4 of 68° C. (155° F.), prior to entering the discharge stack 19 ; and admitting the third treated flue gas mixture FG 3 to the discharge stack 19 at the fourth temperature T 4 .
  • the method for retrofitting includes replacing at least a portion of an outlet duct connecting the flue gas desulfurization system 17 and the discharge stack 19 with a manifold 39 that connects the flue gas desulfurization system 17 , an excess air duct 65 and the discharge stack 19 .
  • the method for retrofitting includes providing a flue gas reheat air particulate removal system 33 , such that the air preheater 13 is in communication with the discharge stack 19 through the flue gas reheat air particulate removal system 33 .
  • Particulate contaminants are removed from the second portion P 2 of air, the particulate contaminants being introduced to the second portion P 2 of air from leakage within the air preheater 13 from the flue gas mixture FG 1 .
  • the method for retrofitting includes a humidity sensor 34 disposed in the communication between the steam generator vessel 11 and the air preheater 13 .
  • the humidity sensor 34 measures the humidity of the flue gas mixture FG 1 to determine a magnitude of first temperature T 1 .
  • the method for retrofitting includes providing an infrared sensor 32 ; and determining, with the infrared sensor, the cold end metal temperature in the air preheater 13 , comparing the cold end metal temperature to the water dew point temperature; and controlling the cold end metal temperature to be no less than the water dew point temperature, with the control unit 71 as described herein.
  • the steam generator system 10 , 10 ′ After implementing the retrofit method, the steam generator system 10 , 10 ′ has a second thermal efficiency that is least as great as a first thermal efficiency of the prior art steam generator system (e.g., the steam generator system 100 , 100 ′ of FIGS. 1 and 2 , respectively) before implementing the retrofit method.
  • a first thermal efficiency of the prior art steam generator system e.g., the steam generator system 100 , 100 ′ of FIGS. 1 and 2 , respectively
  • the present invention also includes another method for improving effectiveness of a steam generator system 10 .
  • the method includes providing a steam generator system 10 that includes the steam generator vessel 11 , the air supply system 13 D, the air preheater 13 , the first particulate removal system 14 , the second particulate removal system 33 , the flue gas desulfurization system 17 , and the flue gas discharge stack 19 .
  • the steam generator system 10 has the air supply system 13 D in communication with the steam generator vessel 11 through the air preheater 13 .
  • the steam generator vessel 11 is in communication with the discharge stack 19 through the air preheater 13 , the first particulate removal system 14 and the flue gas desulfurization system 17 , with the first particulate removal system 14 being located downstream of the air preheater 13 , with the flue gas desulfurization system 17 being located downstream of the first particulate removal system 14 ; with the discharge stack 19 being located downstream of the flue gas desulfurization system 17 and with the air preheater 13 being in communication with the discharge stack 19 through the second particulate removal system 33 .
  • the method includes providing a humidity sensor 34 disposed between the steam generator vessel 11 and the air preheater 13 providing an infrared sensor 32 proximate or in the air preheater 13 .
  • the method includes measuring humidity of a flue gas mixture FG 1 with the humidity sensor to determine a magnitude of a first temperature T 1 .
  • the method includes providing, via the air supply system 13 D, a first amount A 1 of air to the air preheater 13 , the first amount A 1 of air being of a magnitude in excess of that required for combustion of fuel in the steam generator vessel 11 and the air preheater 13 providing the first amount A 1 of air at a mass flow sufficient to establish a first temperature T 1 of a flue gas mixture FG exiting the air preheater 13 , the first temperature T 1 being such that the air preheater has a cold end metal temperature that is no less than a water dew point temperature in the air preheater 13 and such that the cold end metal temperature is less than a sulfuric acid dew point temperature and the first temperature T 1 being from about 105° C. (220° F.) to about 125° C. (257° F.).
  • the method includes determining, with the infrared sensor 32 , the cold end metal temperature in the air preheater 13 , comparing the cold end metal temperature to the water dew point temperature; and controlling the cold end metal temperature to be no less than the water dew point temperature, using the control unit 71 , as described herein.
  • the method includes mitigating SO 3 in the flue gas mixture generated in the steam generator vessel 11 .
  • the mitigating of SO 3 occurs before the flue gas mixture FG enters the air preheater 13 .
  • the air preheater 13 is configured to heat the first amount of air A 1 to a second temperature T 2 of about 288° C. to 399° C. (550° F. to 750° F.).
  • a first portion P 1 of the first amount A 1 of air is supplied as combustion air to the steam generator vessel 11 for combustion of the fuel.
  • the method includes discharging the flue gas mixture FG at the first temperature T 1 , directly from the air preheater 13 to the particulate removal system 14 thereby removing particulate from the flue gas mixture FG and creating a first treated flue gas mixture FG 1 .
  • the first treated flue gas mixture FG 1 is discharged from the particulate removal system 14 directly into the flue gas desulfurization system 17 thereby creating in and discharging from the flue gas desulfurization system 17 , a second treated flue gas mixture FG 2 at a third temperature T 3 of 52° C. to 60° C. (125° F. to 140° F.).
  • the method includes removing particulate contaminants from the second portion P 2 of air.
  • the particulate contaminants being introduced to the second portion P 2 of air from leakage within the air preheater 13 from the flue gas mixture FG 1 .
  • a second portion P 2 of the first amount A 1 of air is injected as flue gas reheat air fed from the air preheater 13 at the second temperature T 2 with the second flue treated flue gas mixture FG 2 at the third temperature T 3 thereby creating third treated flue gas mixture FG 3 at a fourth temperature T 4 of at least 68° C. (155° F.), prior to entering the discharge stack 19 .
  • the third treated flue gas mixture FG 3 is admitted to the discharge stack 19 at the fourth temperature T 4 .
  • a graph generally designated by the numeral 70 has the flue gas reheat air P 2 temperature in degrees Fahrenheit designated on an X-axis 72 and reheat air ratio RR in percentage equal to the mass flow rate W R of flue gas reheat air P 2 (i.e., the second portion P 2 of the first amount A 1 of air) divided by 100 times the mass flow rate WG of scrubbed gas FG 2 leaving the FGD system 17 ( FIGS. 3 and 4 ) at 125° F., on a Y-axis 71 .
  • the graph 70 includes plots for six different increases in temperature DTr of the flue gas FG 2 exiting the FGD 17 ( FIGS. 3 and 4 ).
  • the graph includes a plot 80 for DTr of 5° F., a plot 81 for DTr of 10° F., a plot 82 for DTr of 20° F., a plot 83 for DTr of 30° F.; a plot 84 for DTr of 40° F. and a plot 85 for DTr of 50° F., illustrating the reheat air ratio RR as a function of temperature of the reheat air P 2 .
  • reheat ratio RR ranges from about 1 percent at point 86 (i.e., 800° F., 0.9% for the DTr of 5° F. of the plot 85 ) to about 16 percent at point 87 (i.e., 500° F., 15.9% at 500° F.
  • the RR ranges from about 9 percent at point 88 (i.e., 800° F., 9.1% for the DTr of 50° F. of the plot 85 ) to about 16 percent at point 87 (i.e., 500° F., 15.9% at 500° F. for the DTr of 50° F. of the plot 85 ). While the ranges of reheat ratio RR of 1 percent to 16 percent and 9 percent to 16 percent are shown and described, other ranges of the reheat ratio RR may be employed, depending on the DTr and the temperature of the reheat air P 2 . The inventors arrived at the data points and plots 80 - 85 of FIG. 5 as a result of significant analysis and testing, thereby discovering the surprising results graphically illustrated on the graph 70 of FIG. 5 .
  • a graph 90 has air preheater 13 effectiveness 92 in percentage is shown on an X-axis 92 and temperature in degrees Celsius is shown on a Y-axis 91 for a 1000 MW steam generator system 10 , 10 ′ with a 28° C. (50° F.) temperature rise of the flue gas FG 2 exiting the FGD 17 as a result of the injection of the flue gas reheat air P 2 into the duct 62 between the FGD 17 and the discharge stack 19 .
  • the graph 90 includes a plot 93 of air preheater 13 effectiveness in terms of secondary air P 1 , P 2 temperature T 2 ( FIGS. 3 and 4 ).
  • the graph 90 includes a plot 94 of air preheater 13 effectiveness in terms of flue gas FG outlet temperature T 1 ( FIGS. 3 and 4 ).
  • the inventors have discovered that to maintain the thermal efficiency of the steam generator system 10 , 10 ′ a differential temperature DT of 35° C. between the 150° C. flue gas FG outlet temperature of the prior art steam generator system 100 , 100 ′ (illustrated by dotted line 98 ′′ in the graph 90 ) and the flue gas FG outlet temperature T 1 ( FIGS. 3 and 4 ) of about 105 C (illustrated by dotted line 98 ′ in the graph 90 ) is required.
  • thermal efficiency improvements of the steam generator system 10 , 10 ′ are realized.
  • a thermal efficiency increase is realized at point 94 A of the line 94 at which the flue gas outlet temperature T 1 is 90° C. and the air preheater effectiveness is 97 percent.
  • the increased thermal efficiency and air preheater effectiveness is a result of the first amount of air A 1 being greater than that supplied through prior art air preheaters and/or increased efficiency or increased area of heat transfer elements in the air preheater 13 compared to the heat transfer elements employed in prior art air preheaters.
  • the graph 90 effectiveness of the air preheater 13 and increased thermal efficiency of the steam generator system 10 , 10 ′, compared to prior art steam generator systems 100 , 100 ′, is also realized through an increase in the temperature of the first portion P 1 of the first amount A 1 of air supplied to the steam generator vessel 11 for combustion of the fuel.
  • the Graph 90 includes a plot 93 illustrating an increase in effectiveness of the air preheater 13 as a function of temperature of the first portion P 1 of the first amount A 1 . For example, at point 93 A in which the temperature of the first portion P 1 of the first amount A 1 is 368° C. and the air preheater 13 effectiveness is at 97 percent, an increase in thermal efficiency of the steam generator system 10 , 10 ′ is realized, compared to the prior art steam generator systems 100 , 100 ′.
  • the inventors have surprisingly discovered through ten years of experimentation, analysis and testing a combination of optimum temperature ranges and system configurations for operation of the steam generator system 10 of the present invention that improves the thermal efficiency of the steam generator system compared to prior art steam generator systems such as 100 and 100 ′ while reducing the potential for fouling and visible stack plume.
  • the testing, experimentation and analysis included consideration of: 1) mixing efficiency of the injection of the second portion P 2 of the first amount A 1 of air at the second temperature T 2 with the second flue treated flue gas mixture FG 2 ; 2) fly ash concentrations at various locations in the steam generator system including the amount on the second portion P 2 of air; 3) determination of the amount of the second portion P 2 of air which would provide enough heat to justify removal of the GGH heat exchangers; 4) pressure drops though the steam generator system 10 ; 5) heat loss in the excess air duct 65 ; 6) the effect on fuel combustion in the steam generator vessel; 7) the effect on thermal efficiency of the steam generator system; and 8) efficiency and water supply requirements for the FGD 17 .
  • a first problem is that this level of flue gas temperature reduction (i.e., reducing the temperature of the flue gas exiting the air preheater to 105° C. (220° F.) or less) cannot normally be economically achieved without incremental air flow. There is a practical limit to the amount of heat that can be recovered from flue gas passing through a normal air preheater.
  • Effectiveness Actual Heat Transfer/Maximum Possible Heat Transfer. It is the actual heat transfer to the combustion air that must be maintained or improved, and this is accomplished by a) eliminating the use of cold air steam air preheat or b) the use or more, and/or more highly effective heat transfer surface.
  • a second problem is that there has been no significant demand for incremental, preheated air flow at the plants.
  • the present invention delivers a source of preheated air that can be used for stack gas reheat.
  • a third problem is that for many fuels, a reduction in flue gas temperature leads to significant air preheater fouling and/or corrosion.
  • the present invention makes use of SO 3 mitigation to reduce the SO 3 content to less than or equal to approximately 5 ppmv entering the air preheater. This has been demonstrated to prevent fouling and corrosion at reduced flue gas temperatures well below the dew point of the original flue gas.
  • a fourth problem is that plants without the means for adequate control of the minimum cold end element temperature have experienced severe corrosion due to the condensation of halogen acids at temperatures near the water dew point.
  • the present invention employs a flue gas humidity sensor to establish the water content of the flue gas, which may be used to calculate the water dew point.
  • the dew points of the critical halogen acids (HCl, HF, HBr) may then be estimated using dew point correlations available in literature.
  • the use of an infrared or other sensor may be used to determine the minimum cold end element temperature, which may be compared to the critical dew points.
  • the avoidance of dew point condensation is achieved by a) the use of steam coils to preheat the cold incoming air or 2) the reduction in the amount of preheated air used for stack gas reheat.

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US15/205,243 US10267517B2 (en) 2016-07-08 2016-07-08 Method and system for improving boiler effectiveness
PCT/US2016/055958 WO2018009233A1 (en) 2016-07-08 2016-10-07 Method and system for improving boiler effectiveness
AU2017291660A AU2017291660A1 (en) 2016-07-08 2017-01-13 Method and system for improving boiler effectiveness
SI201730533T SI3482124T1 (sl) 2016-07-08 2017-01-13 Postopek za delovanje in predelavo sistema parnega generatorja
ES17705500T ES2830731T3 (es) 2016-07-08 2017-01-13 Método de funcionamiento y modificación de un sistema de generación de vapor
GBGB1901689.8A GB201901689D0 (en) 2016-07-08 2017-01-13 Method and system for improving boiler effectiveness
JP2019500294A JP2019520543A (ja) 2016-07-08 2017-01-13 ボイラの効率を向上させるための方法及びシステム
ES201990005A ES2738919B1 (es) 2016-07-08 2017-01-13 Método y sistema para mejorar la efectividad de una caldera
PL17705500T PL3482124T3 (pl) 2016-07-08 2017-01-13 Sposób wykorzystywania i sposób modernizacji systemu wytwornicy pary
US16/316,215 US10955136B2 (en) 2016-07-08 2017-01-13 Method and system for improving boiler effectiveness
CN201780000143.4A CN107923610B (zh) 2016-07-08 2017-01-13 用于改善锅炉有效度的方法和系统
EP17705500.1A EP3482124B1 (en) 2016-07-08 2017-01-13 Method for operating and retrofitting a steam generator system
PCT/US2017/013459 WO2018009247A1 (en) 2016-07-08 2017-01-13 Method and system for improving boiler effectiveness
KR1020197002188A KR20190024970A (ko) 2016-07-08 2017-01-13 보일러 효율성을 향상시키는 방법 및 시스템
PL42957217A PL429572A1 (pl) 2016-07-08 2017-01-13 Sposób i układ do poprawy wydajności kotła
PCT/US2017/041078 WO2018009781A1 (en) 2016-07-08 2017-07-07 Method and system for improving boiler effectiveness
PL429398A PL241095B1 (pl) 2016-07-08 2017-07-10 Sposób działania układu generatora pary
EP17743120.2A EP3482125B1 (en) 2016-07-08 2017-07-10 Method for improving boiler effectivness
AU2017292939A AU2017292939A1 (en) 2016-07-08 2017-07-10 Method and system for improving boiler effectivness
GB1901694.8A GB2567104B (en) 2016-07-08 2017-07-10 Method and system for improving boiler effectiveness
PCT/US2017/041332 WO2018009926A1 (en) 2016-07-08 2017-07-10 Method and system for improving boiler effectivness
JP2019500309A JP7152121B2 (ja) 2016-07-08 2017-07-10 ボイラの効率を向上させるための方法及びシステム
CN201780041628.8A CN110036238B (zh) 2016-07-08 2017-07-10 用于改善锅炉有效度的方法和系统
US16/316,170 US20210285637A1 (en) 2016-07-08 2017-07-10 Method and system for improving boiler effectiveness
KR1020197002327A KR102474929B1 (ko) 2016-07-08 2017-07-10 보일러 효율성을 향상시키기 위한 방법 및 시스템
ES201990006A ES2745035R1 (es) 2016-07-08 2017-07-10 Método y sistema para mejorar la efectividad de una caldera
ZA201900378A ZA201900378B (en) 2016-07-08 2019-01-18 Method and system for improving boiler effectiveness
ZA2019/00427A ZA201900427B (en) 2016-07-08 2019-01-21 Method and system for improving boiler effectiveness
JP2021185614A JP7207810B2 (ja) 2016-07-08 2021-11-15 ボイラの効率を向上させるための方法及びシステム
AU2023202632A AU2023202632A1 (en) 2016-07-08 2023-04-28 Method and system for improving boiler effectiveness

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